Pressure and flow control in continuous flow drilling operations

ABSTRACT

A method of providing substantially continuous circulation of fluid through a drill string and an annulus can include sealing off the annulus from atmosphere, regulating flow of the fluid from the annulus, thereby controlling pressure in the wellbore, and diverting flow of the fluid from a pump to an uppermost connector of the drill string and an inlet extending in a sidewall of the drill string, the regulating and the diverting being performed concurrently. A pressure and flow control system can include one or more flow control devices which divert flow from a pump to a valve which selectively permits and prevents communication between an uppermost connector of the drill string and a flow passage extending longitudinally through the drill string, and to a valve which selectively permits and prevents communication between the flow passage and an inlet extending in a sidewall of the drill string.

TECHNICAL FIELD

This disclosure relates generally to equipment utilized and operationsperformed in conjunction with a subterranean well and, in an exampledescribed below, more particularly provides for pressure and flowcontrol in continuous flow drilling operations.

BACKGROUND

It can be beneficial to continuously circulate fluid through a drillstring, in part because ceasing and then restarting flow (such as, toallow a section to be added to or removed from the drill string) cancause detrimental pressure fluctuations in a wellbore being drilled.Therefore, it will be appreciated that improvements are continuallyneeded in the arts of constructing and operating well systems whichprovide for continuous flow during drilling operations.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a representative partially cross-sectional view of a systemand a method for providing substantially continuous circulation througha drill string and an annulus formed between the drill string and awellbore, which system and method can embody principles of thisdisclosure.

FIGS. 2-12 are representative schematic views of various steps of anexample of the method.

FIG. 13 is a representative block diagram of a hydraulic control systemthat may be used with the system and method.

FIGS. 14 & 15 are representative schematic views of steps of anotherexample of the method.

DETAILED DESCRIPTION

FIG. 1 is a representative partially cross-sectional view of a system 10and a method for providing substantially continuous circulation througha drill string 12 and an annulus 14 formed between the drill string anda wellbore 16, which system and method can embody principles of thisdisclosure. However, it should be clearly understood that the system 10and method are merely one example of an application of the principles ofthis disclosure in practice, and a wide variety of other examples arepossible. Therefore, the scope of this disclosure is not limited at allto the details of the system 10 and method described herein and/ordepicted in the drawings.

A land-based well is illustrated in FIG. 1, but it should be clearlyunderstood that the principles of this disclosure can be readily appliedto subsea or other water-based wells, for example, using floating, fixedor jack-up rigs. Thus, the scope of this disclosure is not limited toany particular details of the well depicted in the drawings or describedherein.

In the FIG. 1 example, a section 12 a of the drill string 12 protrudesupwardly from an annular seal device 18 connected above a blowoutpreventer stack 20. The blowout preventer stack 20 depicted in FIG. 1includes an annular preventer 20 a, a variable ram 20 b, a blind ram 20c, a flow spool 20 d and a pipe ram 20 e connected above a wellhead 22.In other examples, other or different equipment could be used in orsubstituted for the annular seal device 18, the blowout preventer stack20 and/or the wellhead 22.

The drill string 12 is used to drill the wellbore 16. For this purpose,a drill bit 24 is connected at a distal end of the drill string 12. Thedrill bit 24 could, for example, be a rotary cone, fixed cutter, impactor other type of drill bit.

In some examples, the drill bit 24 may be rotated by rotating the drillstring 12 at or near the earth's surface, such as, by use of a rotarytable (not shown) or a top drive (not shown). In some examples, thedrill bit 24 may be rotated by use of a drilling motor 26 connected inthe drill string 12. In other examples, the drill bit 24 may not berotated.

Thus, the scope of this disclosure is not limited to any particulartechnique for causing the drill bit 24 to drill the wellbore 16. Indeed,it is not necessary for the drill bit 24 to be used at all. For example,a jet drill (which drills by means of a fluid jet) could be used insteadof, or in addition to, the drill bit 24.

While the wellbore 16 is being drilled, a fluid 28 is pumped through thedrill string 12 into the wellbore 16. The fluid 28 exits the drill bit24 and flows back to the surface via the annulus 14. A non-return valve(unnumbered in FIG. 1) can be used in the drill string to preventreverse flow of the fluid 28 through the drill string 12.

The fluid 28 can serve many purposes, such as, to cool and lubricate thedrill bit 24, to stabilize the wellbore 16, to transport cuttings to thesurface, to maintain a desired pressure in the wellbore, etc. The fluid28 can be combined with a variety of additives, for example, to increaseor decrease the fluid's density, to provide a protective layer or “cake”lining in the wellbore 16, etc. The fluid 28 can be known to thoseskilled in the art as drilling “mud” although it could in some examplesbe merely brine water. Nitrogen or another gas, or another lighterweight fluid, may be added to the fluid 28 for pressure control. Thistechnique is useful, for example, in underbalanced drilling operations.Thus, the scope of this disclosure is not limited to use of anyparticular fluid in the system 10.

The annular seal device 18 seals off the annulus 14 at or near thesurface using, for example, an annular seal (not shown) that encirclesthe drill string 12. The annular seal may or may not rotate with thedrill string 12 when or if the drill string rotates.

The device 18 may be of the type known to those skilled in the art as arotating control device, rotating control head, rotary diverter,rotating blowout preventer, etc. In that case, the device 18 may includebearings (not shown) which allow the annular seal to rotate with thedrill string 12 while sealing off the annulus 14 from atmosphere at ornear the surface. However, it should be clearly understood that thescope of this disclosure is not limited to use of any particular type ofannular seal device in the system 10.

The fluid 28 exits the annulus 14 via an outlet line 44 connected to thedevice 18 (for example, below the annular seal). Since the annulus 14 issealed off at or near the surface with the device 18, a choke manifold46 (not shown in FIG. 1, see FIGS. 2-12) can be used to variablyrestrict the flow of the fluid 28 from the annulus and thereby controlpressure in the wellbore 16.

For example, by increasingly restricting the flow of the fluid 28 fromthe annulus 14, an increased backpressure can be applied to the annulusand, hence, to the wellbore 16. If, however, restriction to flow of thefluid 28 from the annulus 14 is decreased, the backpressure is alsodecreased, thereby decreasing pressure in the wellbore 16.

Control of wellbore pressure is very important in managed pressuredrilling, and in other types of drilling operations. Preferably, thewellbore pressure is accurately controlled to prevent excessive loss offluid into an earth formation surrounding the wellbore 16, undesiredfracturing of the formation, undesired influx of formation fluids intothe wellbore, etc. In typical managed pressure drilling, it is desiredto maintain the wellbore pressure just greater than a pore pressure ofthe formation, without exceeding a fracture pressure of the formation.In typical underbalanced drilling, it is desired to maintain thewellbore pressure somewhat less than the pore pressure, therebyobtaining a controlled influx of fluid from the formation.

Operation of the choke manifold 46 (see FIGS. 2-12) can be automated, sothat a desired pressure is maintained in the wellbore 16 at all, orsubstantially all, times. Suitable automated wellbore pressure controlsystems are described in U.S. Publication No. 2013/0133948, and inInternational Application No. PCT/US12/39586, filed on 25 May 2012. Suchautomated wellbore pressure control systems can be used to automaticallycontrol operation of the choke manifold 46, as well as other pressureand flow equipment (such as, a standpipe manifold 48, not shown in FIG.1, see FIGS. 2-12), including but not limited to flow control devices(such as, valves and chokes) and pumps, etc. However, the scope of thisdisclosure is not limited to use of any particular automated wellborepressure control system.

While the wellbore 16 is being drilled, the fluid 28 can be supplied toan uppermost connector 30 of the drill string 12 via a kelly (not shown)and a standpipe line 32 (see FIGS. 2-12). However, when it is desired toadd another section 12 b to, or to remove the section 12 a from, thedrill string 12, the connector 30 is disconnected from the kelly andstandpipe line 32, and so these are not available for supplying thefluid 28 to the drill string.

In the FIG. 1 example, in order to provide an alternate means forsupplying the fluid 28 to the drill string 12, each section of the drillstring is equipped with a continuous circulation device 34. The device34 includes flow control devices 36, 38 (such as valves or closablechokes) for providing fluid communication between a longitudinal flowpassage 40 of the drill string 12, and the connector 30 and/or an inlet42.

The inlet 42 provides for sealed fluid communication through a sidewallof the device 34 to the flow passage 40. The connector 30 provides forsealed fluid communication through the flow passage 40 between sections12 a,b of the drill string 12.

The flow control device 36 selectively permits and prevents fluidcommunication between the connector 30 and the flow passage 40. The flowcontrol device 38 selectively permits and prevents fluid communicationbetween the inlet 42 and the flow passage 40.

Although separate flow control devices 36, 38 are depicted in FIG. 1,any number of flow control devices could be used in other examples. Forexample, a single three-way valve could be used in place of the separateflow control devices 36, 38 if desired.

Suitable continuous circulation devices are described in U.S. Pat. No.7,845,433, and in International Application No. PCT/US13/62730, filed on30 Sep. 2013. Such continuous circulation devices may be automated (forexample, so that operation of the flow control devices 36, 38 isautomatically controlled), or manually operated. However, the scope ofthis disclosure is not limited to use of any particular type ofcontinuous circulation device.

In the International Application No. PCT/US13/62730 mentioned above, thecontinuous circulation device includes connection sensors that candetect when connections are properly made (for example, at the uppermostconnection 30 and at the inlet 42), so that the valves 36, 38 can beoperated in response. The valves 36, 38 can also be operatedsynchronously. In the system 10 described herein, the valves 36, 38 canbe operated automatically based, at least in part, on an output of ahydraulics model 122 (see FIG. 13).

The sections 12 a,b of the drill string 12 depicted in FIG. 1 may bestands of drill pipe, drill collars or other equipment (such as, thedrilling motor 26, pressure-, measurement- or logging-while-drilling(PWD, MWD or LWD) sensors 50, centralizers, stabilizers, reamers, etc.).The continuous circulation device 34 may be separate from, or integratedas part of, each section added to or removed from the drill string 12 inthe drilling operation. For example, each of the sections 12 a,b of thedrill string 12 illustrated in FIG. 1 can include the continuouscirculation device 34.

As depicted in FIG. 1, the section 12 b is being added to or removedfrom the drill string 12. Thus, the flow control device 36 is closed andthe flow control device 38 is open, thereby enabling flow of the fluid28 via the inlet 42 into the flow passage 40 and preventing upward flowout of the flow passage via the connector 30.

In this example, pressure in the wellbore 16 is maintained relativelyconstant (e.g., with only minor fluctuations occurring) at a desiredpressure while the section 12 b is added to or removed from the drillstring 12. Since continuous circulation of the fluid 28 is provided inthe system 10, the choke manifold 46 (see FIGS. 2-14) can be operated tomaintain a desired pressure in the wellbore 16 while the section 12 b isadded to or removed from the drill string 12.

So that the choke manifold 46 does not have to compensate for largevariations in flow while the flow control devices 36, 38 are operated,the flow of the fluid 28 through the flow passage 40 (and, hence,through the drill string 12 and annulus 14) can be maintainedsubstantially constant (e.g., with only minor fluctuations occurring)while those flow control devices are operated. For example, instead ofopening one of the flow control devices 36, 38 and then closing theother one, the flow control devices can be gradually opened and closed,so that a total amount of flow through the flow control devices remainssubstantially constant. Suitable flow sensors (such as, the sensors 50and flowmeters 52, 54, not shown in FIG. 1, see FIGS. 2-12) and theautomated wellbore pressure control systems mentioned above can be usedto automatically operate the flow control devices 36, 38, so that theflow of the fluid 28 through the drill string 12 and annulus 14 remainssubstantially constant while the flow control devices are operated.

FIGS. 2-12 are representative schematic views of various steps of oneexample of the method. In the FIGS. 2-12 example, a section is added tothe drill string 12. However, it will be readily appreciated by thoseskilled in the art that similar steps can be used in removing a sectionfrom the drill string 12.

Not all of the steps depicted in FIGS. 2-12 are necessary forperformance of the method. For example, FIGS. 14 & 15 depict alternativesteps that can be used with the method in certain circumstances. Thus,it should be clearly understood that the scope of this disclosure is notlimited to any particular number, sequence, function or type of steps inthe method of providing continuous circulation of the fluid 28 throughthe drill string 12 and the annulus 14.

The method steps depicted in FIGS. 2-12 are performed with the system 10of FIG. 1 (including additional equipment described more fully below).However, the method can be performed with other systems, in keeping withthe principles of this disclosure.

Turning now specifically to FIG. 2, the system 10 is representativelyillustrated while the wellbore 16 (see FIG. 1) is being drilled with thedrill string 12, a situation known to those skilled in the art as“drilling ahead” or “making hole.” In this relatively steady statesituation, the fluid 28 is pumped through the drill string 12, into theannulus 14 (see FIG. 1), and returns to the surface.

In the further description below, the flow of the fluid 28 through thesystem 10 will be described, beginning at a reservoir 56 (or “mud pit”)and returning to the reservoir. However, it should be clearly understoodthat a variety of different alternatives exist for flow of the fluid 28,and so the scope of this disclosure is not limited to any particularflow path traversed by the fluid.

Beginning at the reservoir 56, the fluid 28 is pumped by a pump 58 (suchas, a rig mud pump) to the standpipe manifold 48. The fluid 28 passesthrough a debris strainer 60 and a valve 62 in the standpipe manifold48. The fluid 28 then flows to the standpipe line 32.

In this example, a kelly (not shown, but kelly valves 64 a,b aredepicted in FIG. 2) can be connected between the standpipe line 32 andthe section 12 a of drill string 12. The kelly provides a rotary fluidconnection, so that the drill string 12 can rotate relative to thestandpipe line 32 while maintaining fluid communication between them.However, in other examples, such a rotary fluid connection could beprovided as part of a top drive, or a rotary fluid connection may not beused.

The fluid 28 flows from the standpipe line 32 into the flow passage 40of the drill string 12 via the flow control device 36, which is open atthis time. The other flow control device 38 of the continuouscirculation device 34 is closed at this time.

The fluid 28 flows through the passage 40 to the drill bit 24 (see FIG.1). The fluid 28 then exits the drill bit 24 (such as, via nozzles ofthe drill bit, not shown) and returns via the annulus 14 (see FIG. 1).The fluid 28 is shown in dashed lines flowing downwardly and upwardlythrough the blowout preventer stack 20 in FIG. 2, thereby indicating theflow of the fluid into the wellbore 16 (see FIG. 1) via the passage 40,and return of the fluid from the wellbore via the annulus 14.

At or near the surface, the fluid 28 exits the annular seal device 18and flows into the outlet line 44. The fluid 28 then flows through thechoke manifold 46, which variably restricts the fluid flow to therebymaintain a desired pressure in the wellbore 16. In the FIG. 2 example,the fluid 28 flows through only one of multiple redundant chokes 66 ofthe manifold 46. One or more of the chokes 66 can be automaticallyoperated using the wellbore pressure control systems mentioned above, inorder to automatically maintain the desired wellbore pressure.

The fluid 28 then flows through a flowmeter 68. The flowmeter 68 can becapable of relatively precise flow rate measurements (for example, theflowmeter may be a Coriolis flowmeter), which can assist in theautomated operation of the choke manifold 46 and the flow controldevices 36, 38, 62, 74, 82, 86 (see FIGS. 3-15).

In addition, by comparing the flows into the wellbore 16 (measured, forexample, by flowmeters 52, 54 and/or sensors 50) to the flow out of thewellbore (measured, for example, by the flowmeter 68), diagnostictechniques can detect certain circumstances (such as, influx offormation fluid into the wellbore, loss of fluid 28 from the wellbore,etc.), and certain formation properties (such as, fracture pressure,pore pressure, etc.) can be measured. Suitable diagnostic andmeasurement techniques are described in International Application No.PCT/US12/59079, filed on 5 Oct. 2012, and in U.S. Publication No.2013/0133948.

The fluid 28 then flows through a gas separator 70 and a shaker 72before returning to the reservoir 56. The separator 70 removes any gasthat might be entrained in the fluid 28, and the shaker 72 removescuttings or other debris from the fluid. However, other or additionalfluid conditioning equipment may be used, in keeping with the principlesof this disclosure.

Note that the separator 70 could be a 3 or 4 phase separator, or a mudgas separator (sometimes referred to as a “poor boy degasser”). However,the separator 70 is not necessarily used in the system 10.

Referring specifically now to FIG. 3, the system 10 is representativelyillustrated after a flow control device 74 (such as, a choke) has beenopened in the standpipe manifold 48. Note that the fluid 28 flows boththrough the valve 62 and the flow control device 74 at this time.

In addition, a bypass line 80 is now connected to the inlet 42 of thecontinuous circulation device 34. In steps described more fully below,the flow of the fluid 28 is gradually diverted from the standpipe line32 to the bypass line 80, so that the fluid flows into the passage 40via the flow control device 38 instead of via the flow control device36.

Referring specifically now to FIG. 4, the system 10 is representativelyillustrated after the valve 62 has been closed. The fluid 28 now flowsthrough the flow control device 74, but not the valve 62, therebyenabling the flow control device 74 to be used to precisely vary theflow of the fluid 28 as needed.

Referring specifically now to FIG. 5, the system 10 is representativelyillustrated after a valve 76 has been opened in preparation forregulating flow of the fluid 28 to the inlet 42 of the continuouscirculation device 34. However, at this time, the fluid 28 does not yetflow to the inlet 42.

Another flow control device 78, which controls flow through the bypassline 80, may be opened at this time. Alternatively, the flow controldevice 78 could be opened in response to proper connecting of the bypassline 80 to the inlet 42 (e.g., as described in the InternationalApplication No. PCT/US13/62730 mentioned above).

Referring specifically now to FIG. 6, the system 10 is representativelyillustrated after another flow control device 82 (such as, a choke) hasbeen opened, thereby allowing flow of the fluid 28 from the standpipemanifold 48 to the inlet 42 of the continuous circulation device 34. Theflow control device 82 can variably regulate this flow, so that a totalflow of the fluid 28 into the drill string 12 remains substantiallyconstant (although it is not necessary for such flow to remain constant,since the choke manifold 46 can be operated to compensate for flowvariations), and so that large pressure fluctuations are avoided.

The flow control device 74 is depicted in the drawings as being part ofthe standpipe manifold 48, whereas the flow control device 82 isdepicted as being separate from the standpipe manifold. However, it isnot necessary for any particular flow control device to be a part of, orseparate from, the standpipe manifold 48.

The flow control device 38 can be gradually opened while the flowcontrol device 36 is gradually closed, so that fluid communicationbetween the passage 40 and the uppermost connector 30 (see FIG. 1) isgradually prevented and fluid communication between the passage and theinlet 42 is gradually permitted. In addition, the flow control devices74, 82 can be automatically operated, so that progressively more flow ofthe fluid 28 is diverted from the standpipe line 32 to the bypass line80.

Automation of this process can be in response to detection ofappropriate connection of the bypass line 80 to the inlet 42. A suitableconnection sensor is described in the International Application No.PCT/US13/62730 mentioned above.

Referring specifically now to FIG. 7, the system 10 is representativelyillustrated after the flow control device 36 has been fully closed. Allof the flow of the fluid 28 from the standpipe manifold 48 now goes tothe inlet 42, and thence into the flow passage 40. The flow controldevice 74 may also be fully closed at this time. Flow into the inlet 42can now be automatically controlled using the flow control devices 78,82.

Referring specifically now to FIG. 8, the system 10 is representativelyillustrated after a valve 84 in the standpipe manifold 48 has beenclosed, thereby completely isolating the standpipe line 32 from the flowof the fluid 28 from the pump 58. The fluid 28 continues to flow to thebypass line 80 and into the flow passage 40.

After the valve 84 has been closed, the standpipe line 32 can be bledoff (e.g., via a flow control device 86). Once pressure in the standpipeline 32 is reduced to atmospheric pressure, the standpipe line (and thekelly, not shown) can be disconnected from the drill string 12.

This leaves the uppermost connector 30 available for connecting the nextdrill string section 12 b (see FIGS. 1 & 9). Note that FIG. 8 depictsthe system 10 in a same condition as is depicted in FIG. 1.

Referring specifically now to FIG. 9, the system 10 is representativelyillustrated after the section 12 b has been connected to the section 12a. The standpipe line 32 has also been connected to the section 12 b(for example, via an uppermost connector 30 of the section 12 b).However, the fluid 28 continues to flow into the passage 40 exclusivelyvia the bypass line 80, inlet 42 and flow control device 38.

Referring specifically now to FIG. 10, the system 10 is representativelyillustrated after the valve 84 has been opened, allowing the flowcontrol device 74 to variably regulate flow of the fluid 28 from thestandpipe manifold 48 to the standpipe line 32 (which is now connectedto the section 12 b, not shown in FIG. 10).

The flow control device 36 can now be gradually opened to admit fluid 28from the standpipe line 32 to the flow passage 40. The flow controldevice 38 can be gradually closed, so that the fluid 28 eventually flowsinto the passage 40 exclusively via the standpipe line 32 and the flowcontrol device 36. In addition, the flow control devices 74, 82 can beautomatically operated, so that progressively more flow of the fluid 28is diverted from the bypass line 80 to the standpipe line 32.

Automation of this process can be in response to detection ofappropriate connection of the drill string section 12 b to the connector30 of the drill string section 12 a. A suitable connection senor isdescribed in the International Application No. PCT/US13/62730 mentionedabove.

Referring specifically now to FIG. 11, the system 10 is representativelyillustrated after the flow control device 78 has been closed, therebypreventing flow of the fluid 28 via the bypass line 80 to the inlet 42.A bleed valve (not shown) can be incorporated into the inlet 42, or inconjunction with the flow control device 78, in order to bleed thebypass line 80 between the inlet 42 and the flow control device 78.

Note that the flow of the fluid 28 into the drill string 12 at thispoint is exclusively via the standpipe line 32. The flow control device74 can be used to variably regulate this flow as needed.

Referring specifically now to FIG. 12, the system 10 is representativelyillustrated after the bypass line 80 has been disconnected from theinlet 42. In addition, the valve 62 has been opened and the valve 84 hasbeen closed, so that the flow control device 74 is no longer used tovariably regulate the flow of the fluid 28 through the standpipemanifold 48.

The system 10 is now returned to its condition as depicted in FIG. 2,except that the section 12 b (not shown in FIG. 12, but connected abovethe section 12 a) is now part of the drill string 12. Drilling of thewellbore 16 (see FIG. 1) can now resume.

Note that, at any point in the method described above, the flow of thefluid 28 from the annulus 14 (see FIG. 1) can be diverted to a wellcontrol choke manifold 88 (for example, by opening a valve 90 andclosing a valve 92). Flow may be diverted to the well control chokemanifold 88 for well control operations (for example, to circulate outan otherwise uncontrolled influx of gas into the wellbore 16).Alternatively, or in addition, the choke manifold 46 could be used forsuch well control operations.

The hydraulics model 122 (see FIG. 13) can be used, as described morefully below, to determine a pressure applied to the annulus 14 at ornear the surface which will result in a desired wellbore pressure, sothat an operator (or an automated control system) can readily determinehow to regulate the pressure applied to the annulus at or near thesurface (which can be conveniently measured) in order to obtain thedesired wellbore pressure. The hydraulics model 122 can also be used tocontrol various flow control devices (such as, flow control devices 74,82, 86 and valves 36, 38, 62, 76, 78, 84) to maintain continuouscirculation through the drill string 12.

Pressure applied to the annulus 14 can be measured at or near thesurface via a variety of pressure sensors 100, 102, 104, each of whichis in communication with the annulus. Pressure sensor 100 sensespressure below the annular seal device 18, but above the blowoutpreventer stack 20. Pressure sensor 102 senses pressure in the wellhead22 below the blowout preventer stack 20. Pressure sensor 104 sensespressure in the outlet line 44 upstream of the choke manifold 46.

Another pressure sensor 106 senses pressure in the standpipe line 32.Yet another pressure sensor 108 senses pressure downstream of the chokemanifold 46. Additional sensors include temperature sensors 110, 112,Coriolis flowmeter 68, and flowmeters 52, 54, 114, 116, 118.

Not all of these sensors are necessary. For example, the system 10 couldinclude only two of the three flowmeters 52, 54, 114. However, inputfrom the sensors is useful to the hydraulics model 122 in determiningwhat the pressure applied to the annulus 14 should be during thedrilling operation, and how to operate the various flow control devicesin order to maintain a desired wellbore pressure.

In addition, the drill string 12 includes its own sensors 50, forexample, to directly measure wellbore pressure. Such sensors 50 may beof the type known to those skilled in the art as pressure while drilling(PWD), measurement while drilling (MWD) and/or logging while drilling(LWD). These drill string sensor systems generally provide at leastpressure measurement, and may also provide temperature measurement,detection of drill string characteristics (such as vibration, weight onbit, stick-slip, etc.), formation characteristics (such as resistivity,density, etc.) and/or other measurements. Various forms of telemetry(acoustic, pressure pulse, electromagnetic, etc.) may be used totransmit the downhole sensor measurements to the surface.

Additional sensors could be included in the system 10, if desired. Forexample, another flowmeter could be used to measure the rate of flow ofthe fluid 28 exiting the wellhead 22, another Coriolis flowmeter (notshown) could be interconnected directly upstream or downstream of therig mud pump 58, etc.

Fewer sensors could be included in the system 10, if desired. Forexample, the output of the rig mud pump 58 could be determined bycounting pump strokes, instead of by using flowmeter 114 or any otherflowmeters. Thus, the scope of this disclosure is not limited to use ofany particular number, type or arrangement of sensors in the system 10.

FIG. 13 is a representative block diagram of a pressure and flow controlsystem 120 that may be used with the system 10 and method. The controlsystem 120 is preferably fully automated, although some humanintervention may be used, for example, to safeguard against improperoperation, initiate certain routines, update parameters, etc.

The control system 120 includes the hydraulics model 122, a dataacquisition and control interface 124 and a controller 126 (such as aprogrammable logic controller or PLC, a suitably programmed computer,etc.). Although these elements 122, 124, 126 are depicted separately inFIG. 13, any or all of them could be combined into a single element, orthe functions of the elements could be separated into additionalelements, other additional elements and/or functions could be provided,etc.

The hydraulics model 122 is used in the control system 120 to determinethe desired annulus pressure at or near the surface to achieve thedesired wellbore pressure. Data such as well geometry, fluid propertiesand offset well information (such as geothermal gradient and porepressure gradient, etc.) are utilized by the hydraulics model 122 inmaking this determination, as well as real-time sensor data acquired bythe data acquisition and control interface 124.

Thus, there is a continual two-way transfer of data and informationbetween the hydraulics model 122 and the data acquisition and controlinterface 124. For the purposes of this disclosure, it is important toappreciate that the data acquisition and control interface 124 operatesto maintain a substantially continuous flow of real-time data from thesensors 50, 52, 54, 100, 102, 104, 106, 108, 110, 112, 114, 116, 118 tothe hydraulics model 122, so that the hydraulics model has theinformation it needs to adapt to changing circumstances and to updatethe desired annulus pressure, and the hydraulics model operates tosupply the data acquisition and control interface substantiallycontinuously with a value for the desired annulus pressure.

A suitable hydraulics model for use as the hydraulics model 122 in thecontrol system 120 is REAL TIME HYDRAULICS™ provided by HalliburtonEnergy Services, Inc. of Houston, Tex. USA. Another suitable hydraulicsmodel is provided under the trade name IRIS™, and yet another isavailable from SINTEF of Trondheim, Norway. Any suitable hydraulicsmodel may be used in the control system 120 in keeping with theprinciples of this disclosure.

A suitable data acquisition and control interface for use as the dataacquisition and control interface 124 in the control system 120 areSENTRY™ and INSITE™ provided by Halliburton Energy Services, Inc. Anysuitable data acquisition and control interface may be used in thecontrol system 120 in keeping with the principles of this disclosure.

The controller 126 operates to maintain a desired setpoint annuluspressure by controlling operation of the mud return choke 66 whiledrilling. When an updated desired annulus pressure is transmitted fromthe data acquisition and control interface 124 to the controller 126,the controller uses the desired annulus pressure as a setpoint andcontrols operation of the choke 66 in a manner (e.g., increasing ordecreasing flow through the choke as needed) to maintain the setpointpressure in the annulus 14.

This is accomplished by comparing the setpoint pressure to a measuredannulus pressure (such as the pressure sensed by any of the sensors 100,102, 104), and increasing flow through the choke 66 if the measuredpressure is greater than the setpoint pressure, and decreasing flowthrough the choke if the measured pressure is less than the setpointpressure. Of course, if the setpoint and measured pressures are thesame, then no adjustment of the choke 66 is required. This process ispreferably automated, so that no human intervention is required,although human intervention may be used if desired.

The controller 126 may also be used to control operation of the variousstandpipe, bypass and continuous circulation flow control devices andvalves 36, 38, 62, 74, 76, 80, 82, 84, 86. The controller 126 can, thus,be used to automate the processes of appropriately opening and closingthe continuous circulation flow control devices 36, 38 (for example,when the bypass line 80 is properly connected to the inlet 42, etc.),and of diverting flow of the fluid 28 from the standpipe line 32 to thebypass line 80 prior to making a connection in the drill string 12, thendiverting flow from the bypass line to the standpipe line after theconnection is made, and then resuming normal circulation of the fluid 28for drilling. Again, no human intervention may be required in theseautomated processes, other than to initiate each process in turn.

Referring additionally now to FIG. 14, a step in another example of themethod is representatively illustrated. In this step, the fluid 28 isnot continuously circulated through the drill string 12, but is insteaddiverted from the bypass line 80 to the outlet line 44.

Note that FIG. 14 is similar in most respects to FIG. 8, except that aflow control device 94 is opened, thereby allowing the fluid 28 to flowfrom the standpipe manifold 48 via the flow control device 82 to theoutlet line 44. The flow control device 78 is closed, so that the fluid28 does not flow to the inlet 42 (and may not enter the bypass line 80at all).

Backpressure can still be applied to the annulus 14 by variablyregulating flow of the fluid 28 through the choke manifold 46 (andthrough the flow control device 82 and various other flow controldevices), because the valve 92 remains open. Thus, pressure in thewellbore 16 can be maintained at a desired level, even though the fluid28 does not circulate through the drill string 12 and annulus 14.

Although the flow control devices 78, 94 are depicted in FIGS. 2-14 asbeing separate elements of the system 10, they can be combined, ifdesired. In FIG. 15, an alternative configuration of the system 10 isrepresentatively illustrated, in which a single three-way flow controldevice 96 is used in place of the separate flow control devices 78, 94.

Similarly, the flow control devices 74, 82 that variably regulate flowof the fluid 28 from the standpipe manifold 48 to the standpipe line 32and the bypass line 80, respectively, could be combined into a singlethree-way flow control device. Thus, it will be appreciated that thescope of this disclosure is not limited to any particular number,arrangement or configuration of elements in the system 10, or to anyparticular manner of operating those elements in the method.

It can now be fully appreciated that the above disclosure providessignificant advancements to the art of providing continuous circulationof fluid through a drill string and annulus in drilling operations. Thesystem 10 and method examples described above provide for maintainingflow of the fluid 28 through the drill string 12 and annulus 14, evenwhen connections are made or broken in the drill string, or whencirculation might otherwise be ceased. The flow control devices 74, 82can provide for gradual automated diversion of the fluid 28 between thestandpipe line 32 and the bypass line 80, so that fluctuations in flowand/or pressure can be avoided.

More specifically, a method of providing continuous circulation of fluid28 through a drill string 12 and an annulus 14 between the drill string12 and a wellbore 16 is provided to the art by the above disclosure. Inone example, the method comprises: sealing off the annulus 14 fromatmosphere; regulating flow of the fluid 28 from the annulus 14 whilethe annulus is sealed off from the atmosphere, thereby controllingpressure in the wellbore 16; and diverting flow of the fluid 28 from apump 58 to: a) an uppermost connector 30 of the drill string 12, and b)an inlet 42 extending in a sidewall of the drill string 12. Each of theuppermost connector 30 and the inlet 42 is communicable with a flowpassage 40 extending longitudinally through the drill string 12, and theregulating step and the diverting step are performed concurrently.

The diverting step can include gradually decreasing the flow of thefluid 28 from the pump 58 to the uppermost connector 30 while graduallyincreasing the flow of the fluid 28 from the pump 58 to the inlet 42.

The diverting step can include gradually increasing the flow of thefluid 28 from the pump 58 to the uppermost connector 30 while graduallydecreasing the flow of the fluid 28 from the pump 58 to the inlet 42.

The pressure in the wellbore 16 may be maintained substantially constantthroughout the diverting step.

The diverting step can include automatically operating at least one flowcontrol device 74, 82 which controls flow to the uppermost connector 30,and which controls flow to the inlet 42.

A substantially constant flow of the fluid 28 through the drill string12 and the annulus 14 may be maintained throughout the diverting step.

The diverting step may include diverting the flow of the fluid 28 fromthe pump 58 to an outlet line 44 via which the fluid 28 flows from theannulus 14.

Also provided to the art by the above disclosure is a pressure and flowcontrol system 10 for providing continuous circulation of fluid 28 froma pump 58 through a drill string 12 and an annulus 14 between the drillstring 12 and a wellbore 16. In one example, the system 10 can includeat least one flow control device 74, 82 which diverts flow from the pump58 to: a) a first valve (e.g., flow control device 36) which selectivelypermits and prevents communication between an uppermost connector 30 ofthe drill string 12 and a flow passage 40 extending longitudinallythrough the drill string 12, and b) a second valve (e.g., flow controldevice 38) which selectively permits and prevents communication betweenthe flow passage 40 and an inlet 42 extending in a sidewall of the drillstring 12; and an annular seal device 18 which seals off the annulus 14while the one or more flow control devices 74, 82 divert flow betweenthe first and second valves 36, 38.

The first and second valves 36, 38 can be operated in response to sensorinputs to a hydraulics model 122.

The one or more flow control devices may comprise first and secondchokes 74, 82. The first choke 74 can variably regulate flow from thepump 58 to the first valve 36, and the second choke 82 can variablyregulate flow from the pump 58 to the second valve 38.

Flow may be permitted through the first and second chokes 74, 82simultaneously. The first and second chokes 74, 82 may be operated inresponse to sensor 50, 52, 54, 100, 102, 104, 106, 108, 110, 112, 114,116, 118 inputs to a hydraulics model 122. The first and second chokes74, 82 may be operated simultaneously, whereby flow is graduallydiverted between the first and second valves 36, 38.

The system 10 can include a choke 66 which variably regulates flow ofthe fluid 28 from the annular seal device 18 and maintains asubstantially constant pressure in the wellbore 16 while the one or moreflow control devices 74, 82 divert flow between the first and secondvalves 36, 38.

The one or more flow control devices 74, 82 can be automaticallyoperated and maintain a substantially constant flow of the fluid 28through the drill string 12 and the annulus 14 while flow is divertedbetween the first and second valves 36, 38.

In the FIGS. 13 & 14 examples, the one or more flow control devices 74,82 can divert the flow of the fluid 28 from the pump 58 to an outletline 44 via which the fluid 28 flows from the annular seal device 18.

Another method of providing continuous circulation of fluid 28 through adrill string 12 and an annulus 14 between the drill string 12 and awellbore 16 can comprise: sealing off the annulus 14 from atmosphere;regulating flow of the fluid 28 from the annulus 14 while the annulus issealed off from the atmosphere, thereby controlling pressure in thewellbore 16; and operating at least one flow control device 74, 82,thereby diverting flow of the fluid 28 from a pump 58 to: a) a firstvalve (e.g., flow control device 36) which selectively permits andprevents communication between an uppermost connector 30 of the drillstring 12 and a flow passage 40 extending longitudinally through thedrill string 12, and b) a second valve (e.g., flow control device 38)which selectively permits and prevents communication between the flowpassage 40 and an inlet 42 extending in a sidewall of the drill string12. The regulating step and the operating step may be performedconcurrently.

Another method of providing substantially continuous circulation offluid 28 through a drill string 12 and an annulus 14 between the drillstring 12 and a wellbore 16 can comprise: operating a hydraulics model122; and in response to an output from the hydraulics model 122,diverting flow of the fluid 28 from a pump 58 to: a) an uppermostconnector 30 of the drill string 12, and b) an inlet 42 extending in asidewall of the drill string 12. Each of the uppermost connector 30 andthe inlet 42 is communicable with a flow passage 40 extendinglongitudinally through the drill string 12.

Another method of providing substantially continuous circulation offluid 28 through a drill string 12 and an annulus 14 between the drillstring 12 and a wellbore 16 can comprise: inputting sensor measurementsto a hydraulics model 122; and in response to an output of thehydraulics model 122, automatically operating at least one flow controldevice 74, 82, thereby diverting flow of the fluid 28 from a pump 58 to:a) a first valve 36 which selectively permits and prevents communicationbetween an uppermost connector 30 of the drill string 12 and a flowpassage 40 extending longitudinally through the drill string 12, and b)a second valve 38 which selectively permits and prevents communicationbetween the flow passage 40 and an inlet 42 extending in a sidewall ofthe drill string 12.

Although various examples have been described above, with each examplehaving certain features, it should be understood that it is notnecessary for a particular feature of one example to be used exclusivelywith that example. Instead, any of the features described above and/ordepicted in the drawings can be combined with any of the examples, inaddition to or in substitution for any of the other features of thoseexamples. One example's features are not mutually exclusive to anotherexample's features. Instead, the scope of this disclosure encompassesany combination of any of the features.

Although each example described above includes a certain combination offeatures, it should be understood that it is not necessary for allfeatures of an example to be used. Instead, any of the featuresdescribed above can be used, without any other particular feature orfeatures also being used.

It should be understood that the various embodiments described hereinmay be utilized in various orientations, such as inclined, inverted,horizontal, vertical, etc., and in various configurations, withoutdeparting from the principles of this disclosure. The embodiments aredescribed merely as examples of useful applications of the principles ofthe disclosure, which is not limited to any specific details of theseembodiments.

In the above description of the representative examples, directionalterms (such as “above,” “below,” “upper,” “lower,” etc.) are used forconvenience in referring to the accompanying drawings. However, itshould be clearly understood that the scope of this disclosure is notlimited to any particular directions described herein.

The terms “including,” “includes,” “comprising,” “comprises,” andsimilar terms are used in a non-limiting sense in this specification.For example, if a system, method, apparatus, device, etc., is describedas “including” a certain feature or element, the system, method,apparatus, device, etc., can include that feature or element, and canalso include other features or elements. Similarly, the term “comprises”is considered to mean “comprises, but is not limited to.”

Of course, a person skilled in the art would, upon a carefulconsideration of the above description of representative embodiments ofthe disclosure, readily appreciate that many modifications, additions,substitutions, deletions, and other changes may be made to the specificembodiments, and such changes are contemplated by the principles of thisdisclosure. For example, structures disclosed as being separately formedcan, in other examples, be integrally formed and vice versa.Accordingly, the foregoing detailed description is to be clearlyunderstood as being given by way of illustration and example only, thespirit and scope of the invention being limited solely by the appendedclaims and their equivalents.

What is claimed is:
 1. A method of providing substantially continuous circulation of fluid through a drill string and an annulus between the drill string and a wellbore, the method comprising: operating a hydraulics model; and in response to an output from the hydraulics model, diverting flow of the fluid from a pump to: a) an uppermost connector of the drill string, and b) an inlet extending in a sidewall of the drill string, wherein each of the uppermost connector and the inlet is communicable with a flow passage extending longitudinally through the drill string.
 2. The method of claim 1, wherein the diverting further comprises gradually decreasing the flow of the fluid from the pump to the uppermost connector while gradually increasing the flow of the fluid from the pump to the inlet.
 3. The method of claim 1, wherein the diverting further comprises gradually increasing the flow of the fluid from the pump to the uppermost connector while gradually decreasing the flow of the fluid from the pump to the inlet.
 4. The method of claim 1, wherein the pressure in the wellbore is maintained substantially constant throughout the diverting.
 5. The method of claim 1, wherein the diverting further comprises automatically operating at least one flow control device which controls flow to the uppermost connector, and which controls flow to the inlet.
 6. The method of claim 1, wherein a substantially constant flow of the fluid through the drill string and the annulus is maintained throughout the diverting.
 7. The method of claim 1, wherein the diverting further comprises diverting the flow of the fluid from the pump to an outlet line via which the fluid flows from the annulus.
 8. A pressure and flow control system for providing substantially continuous circulation of fluid from a pump through a drill string and an annulus between the drill string and a wellbore, the system comprising: at least one flow control device which diverts flow from the pump to: a) a first valve which selectively permits and prevents communication between an uppermost connector of the drill string and a flow passage extending longitudinally through the drill string, and b) a second valve which selectively permits and prevents communication between the flow passage and an inlet extending in a sidewall of the drill string; and an annular seal device which seals off the annulus while the at least one flow control device diverts flow between the first and second valves.
 9. The system of claim 8, wherein the at least one flow control device comprises first and second chokes, wherein the first choke variably regulates flow from the pump to the first valve, and wherein the second choke variably regulates flow from the pump to the second valve.
 10. The system of claim 9, wherein the first and second chokes are operated in response to sensor inputs to a hydraulics model.
 11. The system of claim 9, wherein the first and second chokes are operated simultaneously, whereby flow is gradually diverted between the first and second valves.
 12. The system of claim 8, wherein the first and second valves are operated in response to sensor inputs to a hydraulics model.
 13. The system of claim 8, wherein the at least one flow control device is automatically operated and maintains a substantially constant flow of the fluid through the drill string and the annulus while flow is diverted between the first and second valves.
 14. The system of claim 8, wherein the at least one flow control device further diverts the flow of the fluid from the pump to an outlet line via which the fluid flows from the annular seal device.
 15. A method of providing substantially continuous circulation of fluid through a drill string and an annulus between the drill string and a wellbore, the method comprising: inputting sensor measurements to a hydraulics model; and in response to an output of the hydraulics model, automatically operating at least one flow control device, thereby diverting flow of the fluid from a pump to: a) a first valve which selectively permits and prevents communication between an uppermost connector of the drill string and a flow passage extending longitudinally through the drill string, and b) a second valve which selectively permits and prevents communication between the flow passage and an inlet extending in a sidewall of the drill string.
 16. The method of claim 15, wherein the diverting further comprises gradually decreasing the flow of the fluid from the pump to the first valve while gradually increasing the flow of the fluid from the pump to the second valve.
 17. The method of claim 15, wherein the diverting further comprises gradually increasing the flow of the fluid from the pump to the first valve while gradually decreasing the flow of the fluid from the pump to the second valve.
 18. The method of claim 15, wherein the pressure in the wellbore is maintained substantially constant throughout the diverting.
 19. The method of claim 15, wherein a substantially constant flow of the fluid through the drill string and the annulus is maintained throughout the diverting.
 20. The method of claim 15, wherein the diverting further comprises diverting the flow of the fluid from the pump to an outlet line via which the fluid flows from the annulus. 